CA1210687A - Viscous oil recovery method - Google Patents
Viscous oil recovery methodInfo
- Publication number
- CA1210687A CA1210687A CA000442625A CA442625A CA1210687A CA 1210687 A CA1210687 A CA 1210687A CA 000442625 A CA000442625 A CA 000442625A CA 442625 A CA442625 A CA 442625A CA 1210687 A CA1210687 A CA 1210687A
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- Canada
- Prior art keywords
- formation
- well
- steam
- injection
- injection well
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
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Abstract
VISCOUS OIL RECOVERY METHOD
ABSTRACT
A subterranean, viscous oil-containing formation is penetrated by at least one injection well extending to the lower portion thereof.
The lower portion of the injection well is characterized by terminating in a cavity in the formation, terminating horizontally or extending through and being in fluid communication with a horizontal fracture through the formation. At least one spaced-apart production well penetrates the formation in fluid communication with the upper two-thirds or less of the formation. A slug of steam is injected into the injection well and fluids including oil are recovered from the formation via the production well. The injection well is then shut-in for a predetermined period of time while continuing production of oil.
Thereafter, a predetermined amount of hot water or low quality steam is injected through the injection well and production is continued until there is an unfavorable amount of water or steam in the fluids recovered.
ABSTRACT
A subterranean, viscous oil-containing formation is penetrated by at least one injection well extending to the lower portion thereof.
The lower portion of the injection well is characterized by terminating in a cavity in the formation, terminating horizontally or extending through and being in fluid communication with a horizontal fracture through the formation. At least one spaced-apart production well penetrates the formation in fluid communication with the upper two-thirds or less of the formation. A slug of steam is injected into the injection well and fluids including oil are recovered from the formation via the production well. The injection well is then shut-in for a predetermined period of time while continuing production of oil.
Thereafter, a predetermined amount of hot water or low quality steam is injected through the injection well and production is continued until there is an unfavorable amount of water or steam in the fluids recovered.
Description
F-2014(2015,2016) -1~
VISCOUS OIL RECOVERY METHOD
This invention relates to a -thermal process ~or recoverin0 oil From a subterranean, viscous oil-containing formation. More particularly, this invention relates to a thermal method o~ recovering oil ~rom a viscous oil-containing formation, especially a highly viscous tar sand deposit, employing an injection system for injecting a thermal fluid into the bottom portion of the formation and a sequence of manipulative steps with steam and hot water to obtain maximum heat utilization and oil recovery from a spaced-apart production well completed in the upper portion of the formation.
Increasing worldwide demand for petroleum products, combined with continuously increasing prices for petroleum and products recovered therefrom, has prompted a renewed interest in the sources of hydrocarbons which are less accessible than crude oil of the Middle East and other countries. One of the largest deposits of such sources of hydrocarbons comprises tar sands and oil shale deposits found in Alberta, Canada, and in the Midwest and Western states of the United States. While the estimated deposits of hydrocarbons contained in tar sands are enormous (e~g., the estimated total of the deposits in Alberta, Canada is 250 billion barrels of synthetlc crude equivalent), only a small proportion of such deposits can be recovered by currently available mining technologies, such as, by strip mining. For example, in lY74, it was estimated that not more than about lO~o of the then estimated 250 billion barrels of synthetic crude equivalent of deposits in Alberta, Canada was recoverable by the then available rnining technologies, SYNTHETIC FUELS, March 1974, pages 3-1 through 3 14). The balance must be recovered by various in-situ techniques such as electrical resistance heating, steam injection and in-situ forward and reverse combustion.
Of the aforementioned ir.-situ recovery methods9 steam ~looding has been a widely-applied method for heavy oil recovery. Problems arise, however, when one attempts to apply the process to heavy oil reservoirs with very low transmissibility such as tar sand deposits. In ., ~. ~ ,. , ~z~
F-2014(2015,2016) -2-such cases, because of the unfavorable mobility ratio, steam channelliny and gravity override often result in early steam breakthrough and leave a large portion of the reservoir unswept. The key ko a successful stearn flooding lies in striking a good balance between the rate of displacement and the rate of heat transfer which lowers the oil viscosity to a more favorable mobility ratio.
Copending Canadian application Serial No. 431,321 discloses a thermal method ~or the recovery of oil from a subterranean, viscous oil-containing ~ormation, wherein steam in an amount ranging from 0.~ to 0.5 pore volume at an injection rate within the range of 4.0 to 7.0 bbl/day/ac.-ft. is injected into the formation via an injection well completed in the lower half of the formation and fluids including oil are recovered via a spaced apart production well completed in the upper half of the formation. The injection well is then shut-in for a variable time and thereafter a predetermined amount of hot water or low quality steam is injected into the formation via the injection well in an amount ranging ~rom 0.0~ to 0.10 pore volume and at an injection rate of 1 to 2.0 bbl/day/ac.-ft. The method is applied to viscous oil-containing formation in which either naturally occurring or induced communication exists bet~een the injection well and the production well in the bottom zone of the formation. The injection well and production well are spaced apart 400 to 750 feet.
Copendin~ Canadian application Serial No. 419,671 discloses a thermal method for the recovery of oil from a subterranean, viscous oil-containing formation, wherein a predetermined amount of steam in an amount not greater than 1.0 pore volume is injected into the formation via an injection well and oil is produced from the formation via a production well. The injection well is then shut-in for a variable time to allow the injected steam to dissipate its heat throughout the formation and reduce oil viscosity while continuing production o~ oil.
A predetermined amount of hot water or low quality steam in an amount not greater than 1.0 pore volume i5 injected into the formation with continued production but avoiding steam breakthrough. Thereafter, production is continued until there is an unfavorable amount of water or steam in the fluids recovered.
~l2~
F-2014 ( 2015, 2016 ) -3-Accordingly, this invention provides an improved thermal system for effectively recoverlng oil ~rom subterranean formations such as tar sand deposits utilizing an injection well and production well completion combined with manipulative steam flooding. The injection well may be characterized by terminating in a cavity in the formation, terminating horizontally or extending through and being in fluid communication with a horizontal fracture in the lower part of the formation.
A subterranean, low transmissibility, viscous oil-containing formation is penetrated by at least one injection well and at least one spaced-apart production well. The production well is completed so that it is in fluid communication with the upper twu-thirds or less of the vertical thickness of the formationl In the embodiment wherein the injection well terminates in a cavity within the formation, said cavity is not to be greater than 0.10 pore volume. Alternately, the lower portion of the formation may be fractured to form a hnrizontal fracture extending radially ~rom and in fluid communication with the injection well. In a ~urther embodiment, the injection well may extend horizontally through the formation for a distance of from about one-third to one-half of the distance between the vertical sections of the injection and production wells.
A slug of steam in an amount within the range of 0.35 to 0.45 pore and at a rate of from 4.5 to 6.5 bbl/day/ac.ft is injected into the cavity in the lower portion formation via the injection well and recovering fluids including oil from the formation via said production well. Simultaneously during injection of the steam into the injection well and fluids are being produced from the production well, a solvent or steam injection-production process may be applied at the production well. This process is ~pplied si~ultaneously with the steam drive process in a series of repetitious cycles throughout the entire time that the steam drive sequence is being applied and particularly in the early stages to enhance production. After the first slug of steam has been injected into the for~ation, the injection well is shut-in for a predetermined period of time and the recovery of ~luids includLng oil is continued from the production well without steam breakthrough.
F-2014(2015,2016~ 4 Thereafter, a predetermined amount, preferably 0.03 to 0.10 pore volume, o~ hot water or low quality steam is injected into the formation via the injection well and fluids including oil are recovered from the ~ormakion via the produotion well. The hot water or low quality steam is injected at a rate of from 1 to 1.5 bbl/day/ac--ft. The slug of hot water or low quality steam may be injected for a plurality of cycles.
Thereafter, production of fluids including oil is continued from the production well until the recovered fluids contain an unfavorable amount of steam or water.
Figure 1 illustrates a subterranean oil-containing formation being subjected to the improved steam flooding techniques in the present invention, penetrated by an injection well in fluid communication with a cavity formed in the bottom portion 3f the formation and a spaced-apart production well in fluid oommunicatinn with the upper portion of the formation.
Figure 2 illustrates Applicant's oil recovery method wherein the formatiGn is penetrated by an injection well having a horizontal fracture extending radially thrnugh the formation therefrom.
, Figure 3 illustrates yet another embodiment of this application wherein the iniection well is deviated in the lower portion of the formation.
Referring to Figure 1, a relatively thick, subterranean, low transmissibility, viscous oil-containing formatinn 10 is penetrated by at least one injection well 12 and at le~st one spaced-apart production well 14. The injection well 12 extends from the earth's surface into the lower portion of the formation 10 and is in fluid co~munication with a cavity 16 ~ormed by a borehole mining technique such as the on~
described in and by A.B. Fly, "Hydro-Blast Mining Shoots Ahead", Mining ~ngineering, pp. 56-58, March (1969). In this method of forming cavity 16~ a bore-hole mining tool is lowered through the injection well 12 into the bottom part of the formation 10. The tool is rotated and sidewall fit streams are sent out at a high speed to cut the formation and wash the cuttings down to the rock pits. This creates a void space or cavity 16 in the bottom part o~ the formation 10 which preferably F-2014(2015,2016) -5-does not extend more than about 1/3 to 1/2 of the distance between the injection well 12 and production well 14. Also, khe vertical thickness of the cavity 16 is not more than 1/5th the vertical thickness of the formation 10. The latter limitations on the size of the cavity 16 creates a cavity no larger than 0.1 pore volume of the reservoir underneath the well pat'cern. The production well 14 is per~orated to establish fluid communication with the upper portion of the formation, not exceeding two-thirds the vertical thickness of the formation.
Referring to Figure 2, the injection well 112 extends from the earth's surfaoe into the lower portion of the formation 110 and is provided with a notch 116 for injection of a fracturing fluid to form a horizontal fracture 118 in the lower portion of the formation. The injection well 112 is first notched by rotating a hydraulic cutting tool to form notch 116. The formation may be hydraulically fractured tn form a radially extending horizontal fracture 118 around the injection well by injection of steam at a very high rate. This method is disclosed in U.S. Patent No. 4,265,310.
Figure 3 depicts a further embodimerlt wherein formation 210 is penetrated by at least one devia~ed injeotion well 212 and at least one spaced-apart production well 214. The injection well 212 extends downwardly ~rom the earth's surface and into the oil containing formation 210 having a substantially vertical section 216 and a substantially horizontal section 218 extending a predetermined distance through the formation near the bottom thereof. The horiæontal section 218 is provided with perforations 220 to establish fluid communication with the lower portion of the formation 210. The horizontal section extends a distance of about one-third to one-half the distance between the vertical section 216 of the injection well 212 and the production well 2140 The horizontal section 21B of the injection well should be completed with a slot liner (not shown) or other sand-control means to prevent blockage of fluid flow such as disclosed in U~S. Patent No.
~,116,275. The production well 214is perforated to establish fluid communication ~ith the upper portion of the formation, not exceeding two~thirds of the vertical thickness of the formation.
.:
F-2014(2015~2016) -6 Once the wells are established, a slug of steam ranging from 0.35 to 0.45 pore volume and preferably 0.37 pore volume is injected into the formation via the injection well and flu.ids including oil are recovered from the formation via production well. The steam is injected at a predetermined rate ranging from 4.5 to 6.5 bbl/day/ac.ft and preferably 5.0 bbl/day/ac.ft. Because of the low transmissibility of the formation, initially the total fluid production rate will be much less khan the injection rate and formation pressure will increase.
Ouring the initial portion o~ the above-described steam injection, the production well may be steam or solvent stimulated by a steam/solvent injection-production sequence or push-pull process. This sequence comprises injecting a predetermined amount of steam or solvent into the formation via the production well and then returning the well to production. The above sequence of steam or solvent injection followed by ~luid production may be repeated for a plurality of cycles.
Suitable solvents include C2 to C10 hydrocarbons and their mixtures, as well as commercial solvents such as kerosene, naph~la and natural gasoline.
After the s}ug of steam has been injected into the ~ormation via injection well, the injection well is shut-in ~or a predetermined period of time and production is continued. This soak-period allows heat to dissipate into the formation further thereby reducing the viscosity of the oil. The high completion, upper two-thirds or less of the formation allows a vertical growth of the steam zone originating from the low viscous finger as pressure decreases and steam rises in the formationO As the heated zone grows, the rate of production increases and the formation pressure is drawn down.
After the injection well has been shut-in for a predetermined period of time and production continued but without steam breakthrough7 a second slug of a heated fluid, preferably hot water or low quality steam, is ;njected into the formation via the injection well and production is continued until there is an unfavorable amount of steam or water in the fluids recovered fro~ the formation via the production well. The quality of the steam injected is not greater than 20%. The amount of heated fluid injected is from 0.03 to 0~10 pore volume at an F-2014(2015,2016) -7~
injection rate of 1 to 1.5 bbl/day/ac.ft. During injection of the heated fluid, the formation will be pressurized and additional mobilized oil will be displaced through the formation for recovery via the production well. It is preferred during this step to inject hot water as the thermal fluid because, unlike steam, it will not migrate upwardly through the formation but is able to appropriate heat: from the steam already present in the formation and cause it to condense thereby deterring steam channeling. This extends the production time by delaying steam breakthrough at the production well. Additional slugs of hot water or low quality steam may be injected into the formation via injection well for a plurality of cycles.
By the term ~Ipore volume" as used herein, is meant that volume of the portion of the formation underlying the well pattern employed as described in greater detail in U.S. Patent No. 3,927,716.
While the invention has been described in terms of a single injection well and a single spaced apart production well, the method according to the invention may be practiced using a variety of well patterns. Any other number of wells, which may be arranged according to any patterns, may be applied in using the present method as illustrated in U.S~ Patent No. 3~927,716. However, if the wells are too far apart, formation communication is usually limited.
VISCOUS OIL RECOVERY METHOD
This invention relates to a -thermal process ~or recoverin0 oil From a subterranean, viscous oil-containing formation. More particularly, this invention relates to a thermal method o~ recovering oil ~rom a viscous oil-containing formation, especially a highly viscous tar sand deposit, employing an injection system for injecting a thermal fluid into the bottom portion of the formation and a sequence of manipulative steps with steam and hot water to obtain maximum heat utilization and oil recovery from a spaced-apart production well completed in the upper portion of the formation.
Increasing worldwide demand for petroleum products, combined with continuously increasing prices for petroleum and products recovered therefrom, has prompted a renewed interest in the sources of hydrocarbons which are less accessible than crude oil of the Middle East and other countries. One of the largest deposits of such sources of hydrocarbons comprises tar sands and oil shale deposits found in Alberta, Canada, and in the Midwest and Western states of the United States. While the estimated deposits of hydrocarbons contained in tar sands are enormous (e~g., the estimated total of the deposits in Alberta, Canada is 250 billion barrels of synthetlc crude equivalent), only a small proportion of such deposits can be recovered by currently available mining technologies, such as, by strip mining. For example, in lY74, it was estimated that not more than about lO~o of the then estimated 250 billion barrels of synthetic crude equivalent of deposits in Alberta, Canada was recoverable by the then available rnining technologies, SYNTHETIC FUELS, March 1974, pages 3-1 through 3 14). The balance must be recovered by various in-situ techniques such as electrical resistance heating, steam injection and in-situ forward and reverse combustion.
Of the aforementioned ir.-situ recovery methods9 steam ~looding has been a widely-applied method for heavy oil recovery. Problems arise, however, when one attempts to apply the process to heavy oil reservoirs with very low transmissibility such as tar sand deposits. In ., ~. ~ ,. , ~z~
F-2014(2015,2016) -2-such cases, because of the unfavorable mobility ratio, steam channelliny and gravity override often result in early steam breakthrough and leave a large portion of the reservoir unswept. The key ko a successful stearn flooding lies in striking a good balance between the rate of displacement and the rate of heat transfer which lowers the oil viscosity to a more favorable mobility ratio.
Copending Canadian application Serial No. 431,321 discloses a thermal method ~or the recovery of oil from a subterranean, viscous oil-containing ~ormation, wherein steam in an amount ranging from 0.~ to 0.5 pore volume at an injection rate within the range of 4.0 to 7.0 bbl/day/ac.-ft. is injected into the formation via an injection well completed in the lower half of the formation and fluids including oil are recovered via a spaced apart production well completed in the upper half of the formation. The injection well is then shut-in for a variable time and thereafter a predetermined amount of hot water or low quality steam is injected into the formation via the injection well in an amount ranging ~rom 0.0~ to 0.10 pore volume and at an injection rate of 1 to 2.0 bbl/day/ac.-ft. The method is applied to viscous oil-containing formation in which either naturally occurring or induced communication exists bet~een the injection well and the production well in the bottom zone of the formation. The injection well and production well are spaced apart 400 to 750 feet.
Copendin~ Canadian application Serial No. 419,671 discloses a thermal method for the recovery of oil from a subterranean, viscous oil-containing formation, wherein a predetermined amount of steam in an amount not greater than 1.0 pore volume is injected into the formation via an injection well and oil is produced from the formation via a production well. The injection well is then shut-in for a variable time to allow the injected steam to dissipate its heat throughout the formation and reduce oil viscosity while continuing production o~ oil.
A predetermined amount of hot water or low quality steam in an amount not greater than 1.0 pore volume i5 injected into the formation with continued production but avoiding steam breakthrough. Thereafter, production is continued until there is an unfavorable amount of water or steam in the fluids recovered.
~l2~
F-2014 ( 2015, 2016 ) -3-Accordingly, this invention provides an improved thermal system for effectively recoverlng oil ~rom subterranean formations such as tar sand deposits utilizing an injection well and production well completion combined with manipulative steam flooding. The injection well may be characterized by terminating in a cavity in the formation, terminating horizontally or extending through and being in fluid communication with a horizontal fracture in the lower part of the formation.
A subterranean, low transmissibility, viscous oil-containing formation is penetrated by at least one injection well and at least one spaced-apart production well. The production well is completed so that it is in fluid communication with the upper twu-thirds or less of the vertical thickness of the formationl In the embodiment wherein the injection well terminates in a cavity within the formation, said cavity is not to be greater than 0.10 pore volume. Alternately, the lower portion of the formation may be fractured to form a hnrizontal fracture extending radially ~rom and in fluid communication with the injection well. In a ~urther embodiment, the injection well may extend horizontally through the formation for a distance of from about one-third to one-half of the distance between the vertical sections of the injection and production wells.
A slug of steam in an amount within the range of 0.35 to 0.45 pore and at a rate of from 4.5 to 6.5 bbl/day/ac.ft is injected into the cavity in the lower portion formation via the injection well and recovering fluids including oil from the formation via said production well. Simultaneously during injection of the steam into the injection well and fluids are being produced from the production well, a solvent or steam injection-production process may be applied at the production well. This process is ~pplied si~ultaneously with the steam drive process in a series of repetitious cycles throughout the entire time that the steam drive sequence is being applied and particularly in the early stages to enhance production. After the first slug of steam has been injected into the for~ation, the injection well is shut-in for a predetermined period of time and the recovery of ~luids includLng oil is continued from the production well without steam breakthrough.
F-2014(2015,2016~ 4 Thereafter, a predetermined amount, preferably 0.03 to 0.10 pore volume, o~ hot water or low quality steam is injected into the formation via the injection well and fluids including oil are recovered from the ~ormakion via the produotion well. The hot water or low quality steam is injected at a rate of from 1 to 1.5 bbl/day/ac--ft. The slug of hot water or low quality steam may be injected for a plurality of cycles.
Thereafter, production of fluids including oil is continued from the production well until the recovered fluids contain an unfavorable amount of steam or water.
Figure 1 illustrates a subterranean oil-containing formation being subjected to the improved steam flooding techniques in the present invention, penetrated by an injection well in fluid communication with a cavity formed in the bottom portion 3f the formation and a spaced-apart production well in fluid oommunicatinn with the upper portion of the formation.
Figure 2 illustrates Applicant's oil recovery method wherein the formatiGn is penetrated by an injection well having a horizontal fracture extending radially thrnugh the formation therefrom.
, Figure 3 illustrates yet another embodiment of this application wherein the iniection well is deviated in the lower portion of the formation.
Referring to Figure 1, a relatively thick, subterranean, low transmissibility, viscous oil-containing formatinn 10 is penetrated by at least one injection well 12 and at le~st one spaced-apart production well 14. The injection well 12 extends from the earth's surface into the lower portion of the formation 10 and is in fluid co~munication with a cavity 16 ~ormed by a borehole mining technique such as the on~
described in and by A.B. Fly, "Hydro-Blast Mining Shoots Ahead", Mining ~ngineering, pp. 56-58, March (1969). In this method of forming cavity 16~ a bore-hole mining tool is lowered through the injection well 12 into the bottom part of the formation 10. The tool is rotated and sidewall fit streams are sent out at a high speed to cut the formation and wash the cuttings down to the rock pits. This creates a void space or cavity 16 in the bottom part o~ the formation 10 which preferably F-2014(2015,2016) -5-does not extend more than about 1/3 to 1/2 of the distance between the injection well 12 and production well 14. Also, khe vertical thickness of the cavity 16 is not more than 1/5th the vertical thickness of the formation 10. The latter limitations on the size of the cavity 16 creates a cavity no larger than 0.1 pore volume of the reservoir underneath the well pat'cern. The production well 14 is per~orated to establish fluid communication with the upper portion of the formation, not exceeding two-thirds the vertical thickness of the formation.
Referring to Figure 2, the injection well 112 extends from the earth's surfaoe into the lower portion of the formation 110 and is provided with a notch 116 for injection of a fracturing fluid to form a horizontal fracture 118 in the lower portion of the formation. The injection well 112 is first notched by rotating a hydraulic cutting tool to form notch 116. The formation may be hydraulically fractured tn form a radially extending horizontal fracture 118 around the injection well by injection of steam at a very high rate. This method is disclosed in U.S. Patent No. 4,265,310.
Figure 3 depicts a further embodimerlt wherein formation 210 is penetrated by at least one devia~ed injeotion well 212 and at least one spaced-apart production well 214. The injection well 212 extends downwardly ~rom the earth's surface and into the oil containing formation 210 having a substantially vertical section 216 and a substantially horizontal section 218 extending a predetermined distance through the formation near the bottom thereof. The horiæontal section 218 is provided with perforations 220 to establish fluid communication with the lower portion of the formation 210. The horizontal section extends a distance of about one-third to one-half the distance between the vertical section 216 of the injection well 212 and the production well 2140 The horizontal section 21B of the injection well should be completed with a slot liner (not shown) or other sand-control means to prevent blockage of fluid flow such as disclosed in U~S. Patent No.
~,116,275. The production well 214is perforated to establish fluid communication ~ith the upper portion of the formation, not exceeding two~thirds of the vertical thickness of the formation.
.:
F-2014(2015~2016) -6 Once the wells are established, a slug of steam ranging from 0.35 to 0.45 pore volume and preferably 0.37 pore volume is injected into the formation via the injection well and flu.ids including oil are recovered from the formation via production well. The steam is injected at a predetermined rate ranging from 4.5 to 6.5 bbl/day/ac.ft and preferably 5.0 bbl/day/ac.ft. Because of the low transmissibility of the formation, initially the total fluid production rate will be much less khan the injection rate and formation pressure will increase.
Ouring the initial portion o~ the above-described steam injection, the production well may be steam or solvent stimulated by a steam/solvent injection-production sequence or push-pull process. This sequence comprises injecting a predetermined amount of steam or solvent into the formation via the production well and then returning the well to production. The above sequence of steam or solvent injection followed by ~luid production may be repeated for a plurality of cycles.
Suitable solvents include C2 to C10 hydrocarbons and their mixtures, as well as commercial solvents such as kerosene, naph~la and natural gasoline.
After the s}ug of steam has been injected into the ~ormation via injection well, the injection well is shut-in ~or a predetermined period of time and production is continued. This soak-period allows heat to dissipate into the formation further thereby reducing the viscosity of the oil. The high completion, upper two-thirds or less of the formation allows a vertical growth of the steam zone originating from the low viscous finger as pressure decreases and steam rises in the formationO As the heated zone grows, the rate of production increases and the formation pressure is drawn down.
After the injection well has been shut-in for a predetermined period of time and production continued but without steam breakthrough7 a second slug of a heated fluid, preferably hot water or low quality steam, is ;njected into the formation via the injection well and production is continued until there is an unfavorable amount of steam or water in the fluids recovered fro~ the formation via the production well. The quality of the steam injected is not greater than 20%. The amount of heated fluid injected is from 0.03 to 0~10 pore volume at an F-2014(2015,2016) -7~
injection rate of 1 to 1.5 bbl/day/ac.ft. During injection of the heated fluid, the formation will be pressurized and additional mobilized oil will be displaced through the formation for recovery via the production well. It is preferred during this step to inject hot water as the thermal fluid because, unlike steam, it will not migrate upwardly through the formation but is able to appropriate heat: from the steam already present in the formation and cause it to condense thereby deterring steam channeling. This extends the production time by delaying steam breakthrough at the production well. Additional slugs of hot water or low quality steam may be injected into the formation via injection well for a plurality of cycles.
By the term ~Ipore volume" as used herein, is meant that volume of the portion of the formation underlying the well pattern employed as described in greater detail in U.S. Patent No. 3,927,716.
While the invention has been described in terms of a single injection well and a single spaced apart production well, the method according to the invention may be practiced using a variety of well patterns. Any other number of wells, which may be arranged according to any patterns, may be applied in using the present method as illustrated in U.S~ Patent No. 3~927,716. However, if the wells are too far apart, formation communication is usually limited.
Claims (10)
PROPERTY OR PRIVILEGE IS CLAIMED, ARE DEFINED AS FOLLOWS:
1. A method of recovering viscous oil from a subterranean, low transmissibility, viscous oil-containing formation comprising:
(a) penetrating the formation with at least one injection well having in its lower region an injection means selected from the group consisting of a cavity established in the formation, a horizontal fracture in the formation radiating from the well and a section of well extending horizontally through the formation;
(b) penetrating the formation with at least one production well spaced apart from said injection well, said production well being in fluid communication with the upper two-thirds or less of the vertical thickness of the formation;
(c) injecting a predetermined amount of steam into the cavity in the lower portion of the formation via said injection well and recovering fluids including oil from the formation via said production well;
(d) subsequently shutting in said injection well and continuing to recover fluids including oil from the formation via said production well for a predetermined period of time and recovering fluids including oil from the formation via the production well without steam breakthrough;
(e) injecting a predetermined amount of a thermal fluid comprising hot water into the formation via said injection well; and (f) continuing to recover fluids including oil from the formation via said production well until the recovered fluids contain an unfavorable amount of steam or water.
(a) penetrating the formation with at least one injection well having in its lower region an injection means selected from the group consisting of a cavity established in the formation, a horizontal fracture in the formation radiating from the well and a section of well extending horizontally through the formation;
(b) penetrating the formation with at least one production well spaced apart from said injection well, said production well being in fluid communication with the upper two-thirds or less of the vertical thickness of the formation;
(c) injecting a predetermined amount of steam into the cavity in the lower portion of the formation via said injection well and recovering fluids including oil from the formation via said production well;
(d) subsequently shutting in said injection well and continuing to recover fluids including oil from the formation via said production well for a predetermined period of time and recovering fluids including oil from the formation via the production well without steam breakthrough;
(e) injecting a predetermined amount of a thermal fluid comprising hot water into the formation via said injection well; and (f) continuing to recover fluids including oil from the formation via said production well until the recovered fluids contain an unfavorable amount of steam or water.
2. The method of claim 1 wherein the horizontal fracture is formed by hydraulic fracture.
3. The method of claim 1 wherein the horizontally extending well section extends a distance between one-third and one-half the distance between the vertical section of the injection well and the production well.
4. The method of claim 1, 2 or 3 wherein the amount of steam injected during step (c) is 0.35 to 0.45 pore volume and the rate of injection is from 4.5 to 6.5 bbl/day/ac--ft.
5. The method of claim 1, 2 or 3 wherein the amount of hot water injected during step (e) is 0.03 to 0.10 pore volume and the injection rate is 1 to 1.5 bbl/day/ac--ft.
6. The method of claim 1, 2 or 3 wherein the thermal fluid injected during step (e) is steam having a quality not greater than 20%
7. The method of claim 1, wherein the cavity extends horizontally from one-third to one-half of the distance between the injection well and the production well and vertically up to 1/5th of the thickness of the formation creating a void space not greater than 0.10 pore volume.
8. The method of claim 1 or 7 wherein the cavity is formed by a bore-hole mining tool lowered through the injection well into the bottom portion of the formation.
9. The method of claim 1 comprising the additional steps of simultaneously injecting a predetermined amount of solvent or steam into the formation via the production well during injection of the steam into the injection well during step (c), recovering fluids including oil from the formation via the production well, and repeating the latter steps for a plurality of cycles.
10. The method of claim 1 wherein step (e) is repeated for a plurality of cycles.
Applications Claiming Priority (6)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US06/447,730 US4489783A (en) | 1982-12-07 | 1982-12-07 | Viscous oil recovery method |
| US06/447,596 US4466485A (en) | 1982-12-07 | 1982-12-07 | Viscous oil recovery method |
| US447,596 | 1982-12-07 | ||
| US06/447,731 US4503910A (en) | 1982-12-07 | 1982-12-07 | Viscous oil recovery method |
| US447,731 | 1982-12-07 | ||
| US447,730 | 1982-12-07 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1210687A true CA1210687A (en) | 1986-09-02 |
Family
ID=27412332
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000442625A Expired CA1210687A (en) | 1982-12-07 | 1983-12-06 | Viscous oil recovery method |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA1210687A (en) |
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10012064B2 (en) | 2015-04-09 | 2018-07-03 | Highlands Natural Resources, Plc | Gas diverter for well and reservoir stimulation |
| US10344204B2 (en) | 2015-04-09 | 2019-07-09 | Diversion Technologies, LLC | Gas diverter for well and reservoir stimulation |
| US10982520B2 (en) | 2016-04-27 | 2021-04-20 | Highland Natural Resources, PLC | Gas diverter for well and reservoir stimulation |
-
1983
- 1983-12-06 CA CA000442625A patent/CA1210687A/en not_active Expired
Cited By (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10012064B2 (en) | 2015-04-09 | 2018-07-03 | Highlands Natural Resources, Plc | Gas diverter for well and reservoir stimulation |
| US10344204B2 (en) | 2015-04-09 | 2019-07-09 | Diversion Technologies, LLC | Gas diverter for well and reservoir stimulation |
| US10385258B2 (en) | 2015-04-09 | 2019-08-20 | Highlands Natural Resources, Plc | Gas diverter for well and reservoir stimulation |
| US10385257B2 (en) | 2015-04-09 | 2019-08-20 | Highands Natural Resources, PLC | Gas diverter for well and reservoir stimulation |
| US10982520B2 (en) | 2016-04-27 | 2021-04-20 | Highland Natural Resources, PLC | Gas diverter for well and reservoir stimulation |
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